Growth in global LNG export capacity will be limited in 2023:
In 2023, four new liquefied natural gas (LNG) export projects are expected to come online worldwide, with a combined capacity of 1.0 billion cubic feet per day (Bcf/d), according to our estimates based on trade press and company press releases. The total annual LNG capacity additions will be the lowest since 2013, when 0.7 Bcf/d of new export capacity was placed in service, according to the International Group of Liquefied Natural Gas Importers (GIIGNL). Between 2014 and 2022, annual LNG capacity additions ranged from a low of 1.8 Bcf/d in 2021 to a high of 5.6 Bcf/d in 2018. New LNG export projects that are expected to come online this year include: The Greater Tortue Floating LNG (FLNG) production unit located offshore Mauritania and Senegal (0.3 Bcf/d capacity). The Tango Floating LNG production unit located offshore the Republic of Congo (0.1 Bcf/d capacity). The Tango FLNG was previously used to produce LNG in Argentina in 2019–2020. Tangguh LNG Train 3 in West Papua, Indonesia (0.5 Bcf/d capacity), which will expand the existing project. Sengkang LNG in South Sulawesi, Indonesia (0.1 Bcf/d capacity). This project was designed to include four liquefaction trains, each with capacity of 66 million cubic feet per day (MMcf/d). However, construction has started on only the first train, and the completion timeline of the project has been extended several times. In 2022, three new LNG export projects with a combined capacity of 2.2 Bcf/d came online in the United States, Russia, and Mozambique. In the United States, Calcasieu Pass LNG with a peak production capacity of 1.6 Bcf/d started production from its 18 mid-scale liquefaction trains. In Russia, Portovaya LNG (0.2 Bcf/d capacity) started production in the summer and loaded its first LNG cargo in September 2022. In Mozambique, Coral South Floating LNG production unit 1 (capacity 0.4 Bcf/d) loaded its first cargo in November 2022. In the last 11 years (2012–2022), Australia and the United States led the growth in global LNG capacity by adding a combined 22.7 Bcf/d of LNG export capacity that accounted for 75% of the total global capacity additions over this period. Regionally, countries in Africa—Algeria, Angola, Cameroon, and Mozambique—built 2.7 Bcf/d of new LNG export capacity over this period, while Russia added 2.6 Bcf/d. Countries in the Asia Pacific region (excluding Australia) added a combined 2.4 Bcf/d of LNG export capacity. The United States began exporting LNG in February 2016, and within seven years developed the world’s largest LNG export capacity, overtaking Australia and Qatar, with seven LNG export facilities totaling 13.9 Bcf/d of peak production capacity. In 2024–2025, we expect fewer global LNG export capacity additions than in previous years. We expect U.S. LNG export capacity to grow as three projects currently under construction are completed. One LNG export project in Russia—Arctic LNG 2—which started construction in 2017, has been delayed and is now tentatively targeting 2023–2026 for bringing its three LNG trains online. New LNG export projects in Canada and Mexico are also expected to be placed into service by 2025–2026.
Henry Hub spot price: The Henry Hub spot price fell 42 cents from $3.08 per million British thermal units (MMBtu) last Wednesday to $2.66/MMBtu yesterday. Henry Hub futures prices: The February 2023 NYMEX contract expired Friday at $3.109/MMBtu, up 4 cents from last Wednesday. The March 2023 NYMEX contract price decreased to $2.468/MMBtu, down 45 cents from last Wednesday to yesterday. The price of the 12-month strip averaging March 2023 through February 2024 futures contracts declined 25 cents to $3.268/MMBtu. Select regional spot prices: Natural gas spot prices fell at most locations this report week (Wednesday, January 25 to Wednesday, February 1), but increases were seen in both the West and Northeast. Week-over-week price changes ranged from a decrease of $3.62/MMBtu at Sumas to an increase of $7.93/MMBtu at the Algonquin Citygate. In the Northeast, at the Algonquin Citygate, which serves Boston-area consumers, the price went up $7.93 from $4.23/MMBtu last Wednesday to $12.16/MMBtu yesterday. At the transcontinental Pipeline Zone 6 trading point for New York City, the price increased $1.53 from $3.08/MMBtu last Wednesday to $4.61/MMBtu yesterday. Prices were volatile this report week, reflecting rapid changes in temperatures in the region. The Algonquin Citygate price reached a weekly low of $3.22/MMBtu on Friday, before rising to a weekly high of $13.49/MMBtu on Tuesday. Temperatures in the Boston Area averaged 37°F this report week, 8°F above normal, which resulted in 57 fewer heating degree days (HDD) than normal. The short term-forecast calls for wind chills into the minus 50s this weekend in northern parts of New England, contributing to the week-over-week price increase. Tennessee Gas Pipeline and Transcontinental Gas Pipeline Company have issued operational flow orders, effective January 31 and February 3, respectively, to protect the integrity of their pipeline systems from a rapid increase in anticipated natural gas demand for space heating as a result of the winter storm currently affecting portions of Texas and the Midwest and moving into the region at the end of the week. Natural gas price changes in the West were mixed. The price at PG&E Citygate in Northern California rose $1.42, up from $15.32/MMBtu last Wednesday to $16.74/MMBtu yesterday. The price at SoCal Citygate in Southern California increased $1.73 from $16.77/MMBtu to $18.50/MMBtu yesterday. The price at Sumas on the Canada-Washington border fell $3.62 from $14.53/MMBtu last Wednesday to $10.91/MMBtu yesterday. After being elevated for several weeks, prices in these markets fell to weekly lows last Thursday of $6.63/MMBtu (Sumas), $8.03/MMBtu (PG&E Citygate) and $8.32/MMBtu (SoCal Citygate). Westcoast Energy Inc., which delivers natural gas into the Pacific Northwest at Sumas, plans to return the T-South pipeline (approximately 2 Bcf/d of capacity) to full service on February 3. In turn, Northwest Pipeline, which receives that natural gas at the border and delivers it south, lifted an overrun entitlement issued on January 31 as a result of the unplanned outage on T-South. An overrun entitlement is a requirement that shippers’ scheduled receipts and deliveries of natural gas be equal for a period of time. Northwest Pipeline also delivers gas from the Rockies to the Pacific Northwest and reinstated an overrun entitlement warning north of the Kemmerer compressor station in Lincoln County, Wyoming. The price at the Waha Hub in West Texas, which is located near Permian Basin production activities, remained flat at $2.37/MMBtu. The Waha Hub traded 29 cents below the Henry Hub price yesterday, compared to last Wednesday when it traded 71 cents below the Henry Hub price. On Monday, the Waha hub price reached $3.28 and traded 47 cents above the Henry Hub price. Natural gas production in Texas decreased 3% (0.7 Bcf/d) week over week, led by a 4% (0.2 Bcf/d) decline in the Permian Basin, according to data from S&P Global Commodity Insights. Total consumption increased 11% (1.3 Bcf/d) week over week. Natural gas consumption in the electric power sector rose 14% (0.7 Bcf/d) and consumption in the residential and commercial sectors increased 29% (0.7 Bcf/d).
Daily spot prices by region are available on the EIA website.
International futures prices: International natural gas futures prices decreased this report week. According to Bloomberg Finance, L.P., weekly average front-month futures prices for liquefied natural gas (LNG) cargoes in East Asia decreased $2.99 to a weekly average of $19.43/MMBtu. Natural gas futures for delivery at the Title Transfer Facility (TTF) in the Netherlands, the most liquid natural gas market in Europe, decreased $1.64/MMBtu to a weekly average of $18.04/MMBtu. In the same week last year (week ending February 2, 2022), the prices in East Asia and at TTF were $24.94/MMBtu and $27.80/MMBtu, respectively. Natural gas plant liquids (NGPL) prices: The natural gas plant liquids composite price at Mont Belvieu, Texas, fell by 9 cents/MMBtu, averaging $8.25/MMBtu for the week ending February 1. Ethane prices fell 1%, while average weekly natural gas prices at the Houston Ship Channel fell 11% week over week, widening the ethane premium to natural gas by 22%. Ethylene spot prices remained relatively unchanged, widening the ethylene to ethane premium by 1%. Propane prices remained relatively unchanged, while the weekly average price of Brent crude oil fell 2%, resulting in a 4% decrease in the propane discount relative to crude oil. Normal butane and isobutane prices fell 1%, while natural gasoline prices fell 3%.
Supply and Demand
Supply: According to data from S&P Global Commodity Insights, the average total supply of natural gas fell by 1.2% (1.3 Bcf/d) compared with the previous report week. Dry natural gas production decreased by 1.9% (1.9 Bcf/d), as a result of below-normal temperatures and freeze-offs in producing regions. Average net imports from Canada increased by 11.8% (0.6 Bcf/d) from last week. Demand: Total U.S. consumption of natural gas rose by 6.7% (6.7 Bcf/d) compared with the previous report week, according to data from S&P Global Commodity Insights. Natural gas consumed for power generation rose 1.9% (0.6 Bcf/d) week over week. Industrial sector consumption increased by 2.5% (0.6 Bcf/d), and consumption in the residential and commercial sectors increased by 13.1% (5.5 Bcf/d) as below-normal temperatures spread across much of the United States this week. Natural gas exports to Mexico decreased 2.5% (0.1 Bcf/d). Natural gas deliveries to U.S. LNG export facilities (LNG pipeline receipts) averaged 12.7 Bcf/d, or 0.2 Bcf/d higher than last week.
Liquefied Natural Gas (LNG)
Pipeline receipts: Overall natural gas deliveries to U.S. LNG export terminals increased by 1.2% (0.2 Bcf/d) week over week to 12.7 Bcf/d. Feedgas deliveries to terminals in South Louisiana, rising by 1.2% (0.1 Bcf/d) week over week to 9.0 Bcf/d were largely responsible for the increase, while deliveries to all other terminals were essentially flat, according to data from S&P Global Commodity Insights. Vessels departing U.S. ports: Twenty LNG vessels (eight from Sabine Pass, four from Cameron, three from Calcasieu Pass, two each from Corpus Christi and Cove Point, and one from Elba Island) with a combined LNG-carrying capacity of 74 Bcf departed the United States between January 26 and February 1, according to shipping data provided by Bloomberg Finance, L.P.
LNG terminals: On February 1, Freeport LNG received approval from the Federal Energy Regulatory Commission (FERC) to begin commissioning, including cooldown, of the LNG piping system and LNG train 3. Additional authorizations are still needed to restart operations.
The net withdrawals from storage totaled 151 Bcf for the week ending January 27, compared with the five-year (2018–2022) average net withdrawals of 181 Bcf and last year’s net withdrawals of 261 Bcf during the same week. Working natural gas stocks totaled 2,583 Bcf, which is 163 Bcf (7%) more than the five-year average and 222 Bcf (9%) more than last year at this time. According to The Desk survey of natural gas analysts, estimates of the weekly net change to working natural gas stocks ranged from net withdrawals of 131 Bcf to 159 Bcf, with a median estimate of 142 Bcf. The average rate of withdrawals from storage is 22% lower than the five-year average so far in the withdrawal season (November through March). If the rate of withdrawals from storage matched the five-year average of 14.1 Bcf/d for the remainder of the withdrawal season, the total inventory would be 1,695 Bcf on March 31, which is 163 Bcf higher than the five-year average of 1,532 Bcf for that time of year.